Maximize condensate recovery in gas reservoirs by injection of variable flue gas composition

ABSTRACT

A method to improve production of condensate is disclosed. The method includes obtaining a condensate fluids sample from a gas condensate reservoir, generating, from a laboratory pressure, volume and temperature (PVT) experiment of the condensate fluids sample, a liquid dropout curve, performing simulation of the laboratory PVT experiment based on Equations of State (EoS) of the condensate to generate a simulated liquid dropout curve, where the EoS is adjusted to match the simulated liquid dropout curve and the liquid dropout curve generated by the laboratory PVT experiment, performing, based on the adjusted EoS, a reservoir simulation of the gas condensate reservoir under injection of flue gas, where the reservoir simulation models a condensate banking phenomenon to generate an optimal flue gas ratio that maximizes a measure of condensate production, and facilitating, based on the optimal flue gas ratio, the production of the condensate in the gas condensate reservoir.

BACKGROUND

Condensate is a low density and high API gravity (American PetroleumInstitute gravity) hydrocarbon generally found in a gas reservoir. Gasreservoirs producing condensate in gas wells are referred to as gascondensate reservoirs. While the term “condensate” often refers to theliquid form of the low density and high API gravity hydrocarbon found ingas condensate reservoirs, the term “condensate” is broadened throughoutthis disclosure to describe all phases of such hydrocarbon in gascondensate reservoirs.

When reservoir pressure drops below the dew point during gas reservoirproduction, Condensate changes from gaseous phase to liquid phase (i.e.,precipitates) in the reservoir around the well and rapidly accumulatesas freshly produced gas continues to deposit additional liquidcondensate near the well. The accumulation of liquid condensate near thewell is referred to as the condensate banking phenomenon, which reducesthe gas saturation and the gas well productivity.

Flue gas is the mixture of gases resulting from combustion and otherreactions in a furnace, passing off through the smoke flue, and composedlargely of nitrogen, carbon dioxide, carbon monoxide, water vapor, andoften sulfur dioxide.

SUMMARY

In general, in one aspect, the invention relates to a method to improveproduction of condensate in a gas condensate reservoir. The methodincludes obtaining a condensate fluids sample from the gas condensatereservoir, generating, from a laboratory pressure, volume andtemperature (PVT) experiment of the condensate fluids sample, a liquiddropout curve of the condensate fluids sample, performing simulation ofthe laboratory PVT experiment based on Equations of State (EoS) of thecondensate to generate a simulated liquid dropout curve, wherein the EoSis adjusted to match the simulated liquid dropout curve and the liquiddropout curve generated by the laboratory PVT experiment, performing,based on the adjusted EoS, a reservoir simulation of the gas condensatereservoir under injection of flue gas, wherein the reservoir simulationmodels a condensate banking phenomenon to generate an optimal flue gasratio that maximizes a measure of condensate production, andfacilitating, based on the optimal flue gas ratio, the production of thecondensate in the gas condensate reservoir.

In general, in one aspect, the invention relates to a reservoirsimulator to improve production of condensate in a gas condensatereservoir. The reservoir simulator includes a computer processor, andmemory storing instructions, when executed, causing the computerprocessor to perform, based on Equations of State (EoS) of thecondensate, simulation of a laboratory pressure, volume and temperature(PVT) experiment of a condensate fluids sample obtained from the gascondensate reservoir to generate a simulated liquid dropout curve,wherein the EoS is adjusted to match the simulated liquid dropout curveand a liquid dropout curve generated by performing the laboratory PVTexperiment, perform, based on the adjusted EoS, a reservoir simulationof the gas condensate reservoir under injection of flue gas, wherein thereservoir simulation models a condensate banking phenomenon to generatean optimal flue gas ratio that maximizes a measure of condensateproduction, and facilitate, based on the optimal flue gas ratio, theproduction of the condensate in the gas condensate reservoir.

In general, in one aspect, the invention relates to a system thatincludes a wellsite for production of condensate in a gas condensatereservoir, and a reservoir simulator comprising a computer processor andmemory storing instructions, when executed, causing the computerprocessor to perform, based on Equations of State (EoS) of thecondensate, simulation of a laboratory pressure, volume and temperature(PVT) experiment of a condensate fluids sample obtained from the gascondensate reservoir to generate a simulated liquid dropout curve,wherein the EoS is adjusted to match the simulated liquid dropout curveand a liquid dropout curve generated by performing the laboratory PVTexperiment, perform, based on the adjusted EoS, a reservoir simulationof the gas condensate reservoir under injection of flue gas, wherein thereservoir simulation models a condensate banking phenomenon to generatean optimal flue gas ratio that maximizes a measure of condensateproduction, and facilitate, based on the optimal flue gas ratio, theproduction of the condensate in the gas condensate reservoir.

Other aspects and advantages of the claimed subject matter will beapparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

Specific embodiments of the disclosed technology will now be describedin detail with reference to the accompanying figures. Like elements inthe various figures are denoted by like reference numerals forconsistency.

FIGS. 1A-1B show a system in accordance with one or more embodiments.

FIG. 2 shows a method flowchart in accordance with one or moreembodiments.

FIGS. 3A-3C shows an example in accordance with one or more embodiments.

FIG. 4 shows a computing system in accordance with one or moreembodiments.

DETAILED DESCRIPTION

In the following detailed description of embodiments of the disclosure,numerous specific details are set forth in order to provide a morethorough understanding of the disclosure. However, it will be apparentto one of ordinary skill in the art that the disclosure may be practicedwithout these specific details. In other instances, well-known featureshave not been described in detail to avoid unnecessarily complicatingthe description.

Throughout the application, ordinal numbers (for example, first, second,third) may be used as an adjective for an element (that is, any noun inthe application). The use of ordinal numbers is not to imply or createany particular ordering of the elements nor to limit any element tobeing only a single element unless expressly disclosed, such as usingthe terms “before”, “after”, “single”, and other such terminology.Rather, the use of ordinal numbers is to distinguish between theelements. By way of an example, a first element is distinct from asecond element, and the first element may encompass more than oneelement and succeed (or precede) the second element in an ordering ofelements.

In general, embodiments of the disclosure include systems and methodsfor improving recovery of condensate in a gas reservoir based on fluegas injection that modifies the reservoir fluid phase envelope. In oneor more embodiments of the disclosure, flue gas is injected into a gascondensate reservoir to adjust the saturation or critical point locationon a Pressure-Temperature (P-T) envelope in the reservoir to mitigateimpact of condensate banking phenomena.

FIG. 1A shows a schematic diagram in accordance with one or moreembodiments. More specifically, FIG. 1A illustrates a well environment(100) that includes a hydrocarbon reservoir (“reservoir”) (102) locatedin a subsurface hydrocarbon-bearing formation (“formation”) (104) and awell system (106). In one or more embodiments of the disclosure, thereservoir (102) is a gas reservoir to produce condensate, referred to asa gas condensate reservoir. The hydrocarbon-bearing formation (104) mayinclude a porous or fractured rock formation that resides underground,beneath the earth's surface (“surface”) (108). In the case of the wellsystem (106) being a hydrocarbon well, the reservoir (102) may include aportion of the hydrocarbon-bearing formation (104). Thehydrocarbon-bearing formation (104) and the reservoir (102) may includedifferent layers of rock having varying characteristics, such as varyingdegrees of permeability, porosity, capillary pressure, and resistivity.In the case of the well system (106) being operated as a productionwell, the well system (106) may facilitate the extraction ofhydrocarbons (or “production”) from the reservoir (102).

In some embodiments, the well system (106) includes a wellbore (120), awell sub-surface system (122), a well surface system (124), and a wellcontrol system (“control system”) (126). The control system (126) maycontrol various operations of the well system (106), such as wellproduction operations, well completion operations, well maintenanceoperations, and reservoir monitoring, assessment and developmentoperations. In some embodiments, the control system (126) includes acomputer system that is the same as or similar to that of computersystem (900) described below in FIG. 4 and the accompanying description.

The wellbore (120) may include a bored hole that extends from thesurface (108) into a target zone of the hydrocarbon-bearing formation(104), such as the reservoir (102). An upper end of the wellbore (120),terminating at or near the surface (108), may be referred to as the“up-hole” end of the wellbore (120), and a lower end of the wellbore,terminating in the hydrocarbon-bearing formation (104), may be referredto as the “down-hole” end of the wellbore (120). The wellbore (120) mayfacilitate the circulation of drilling fluids during drillingoperations, the flow of hydrocarbon production (“production”) (121)(e.g., oil and gas) from the reservoir (102) to the surface (108) duringproduction operations, the injection of substances (e.g., water) intothe hydrocarbon-bearing formation (104) or the reservoir (102) duringinjection operations, or the communication of monitoring devices (e.g.,logging tools) into the hydrocarbon-bearing formation (104) or thereservoir (102) during monitoring operations (e.g., during in situlogging operations).

In some embodiments, during operation of the well system (106), thecontrol system (126) collects and records wellhead data (140) for thewell system (106). The wellhead data (140) may include, for example, arecord of measurements of wellhead pressure (P_(wh)) (e.g., includingflowing wellhead pressure), wellhead temperature (T_(wh)) (e.g.,including flowing wellhead temperature), wellhead production rate(Q_(wh)) over some or all of the life of the well (106), and water cutdata. In some embodiments, the measurements are recorded in real-time,and are available for review or use within seconds, minutes or hours ofthe condition being sensed (e.g., the measurements are available within1 hour of the condition being sensed). In such an embodiment, thewellhead data (140) may be referred to as “real-time” wellhead data(140). Real-time wellhead data (140) may enable an operator of the well(106) to assess a relatively current state of the well system (106), andmake real-time decisions regarding development of the well system (106)and the reservoir (102), such as on-demand adjustments in regulation ofproduction flow from the well.

In some embodiments, the well sub-surface system (122) includes casinginstalled in the wellbore (120). For example, the wellbore (120) mayhave a cased portion and an uncased (or “open-hole”) portion. The casedportion may include a portion of the wellbore having casing (e.g.,casing pipe and casing cement) disposed therein. The uncased portion mayinclude a portion of the wellbore not having casing disposed therein. Insome embodiments, the casing includes an annular casing that lines thewall of the wellbore (120) to define a central passage that provides aconduit for the transport of tools and substances through the wellbore(120). For example, the central passage may provide a conduit forlowering logging tools into the wellbore (120), a conduit for the flowof production (121) (e.g., oil and gas) from the reservoir (102) to thesurface (108), or a conduit for the flow of injection substances (e.g.,water) from the surface (108) into the hydrocarbon-bearing formation(104). In some embodiments, the well sub-surface system (122) includesproduction tubing installed in the wellbore (120). The production tubingmay provide a conduit for the transport of tools and substances throughthe wellbore (120). The production tubing may, for example, be disposedinside casing. In such an embodiment, the production tubing may providea conduit for some or all of the production (121) (e.g., oil and gas)passing through the wellbore (120) and the casing.

In some embodiments, the well surface system (124) includes a wellhead(130). The wellhead (130) may include a rigid structure installed at the“up-hole” end of the wellbore (120), at or near where the wellbore (120)terminates at the Earth's surface (108). The wellhead (130) may includestructures for supporting (or “hanging”) casing and production tubingextending into the wellbore (120). Production (121) may flow through thewellhead (130), after exiting the wellbore (120) and the wellsub-surface system (122), including, for example, the casing and theproduction tubing. In some embodiments, the well surface system (124)includes flow regulating devices that are operable to control the flowof substances into and out of the wellbore (120). For example, the wellsurface system (124) may include one or more production valves (132)that are operable to control the flow of production (121). For example,a production valve (132) may be fully opened to enable unrestricted flowof production (121) from the wellbore (120), the production valve (132)may be partially opened to partially restrict (or “throttle”) the flowof production (121) from the wellbore (120), and production valve (132)may be fully closed to fully restrict (or “block”) the flow ofproduction (121) from the wellbore (120), and through the well surfacesystem (124).

In some embodiments, the wellhead (130) includes a choke assembly. Forexample, the choke assembly may include hardware with functionality foropening and closing the fluid flow through pipes in the well system(106). Likewise, the choke assembly may include a pipe manifold that maylower the pressure of fluid traversing the wellhead. As such, the chokeassembly may include set of high pressure valves and at least twochokes. These chokes may be fixed or adjustable or a mix of both.Redundancy may be provided so that if one choke has to be taken out ofservice, the flow can be directed through another choke. In someembodiments, pressure valves and chokes are communicatively coupled tothe well control system (126). Accordingly, a well control system (126)may obtain wellhead data regarding the choke assembly as well astransmit one or more commands to components within the choke assembly inorder to adjust one or more choke assembly parameters.

Keeping with FIG. 1A, in some embodiments, the well surface system (124)includes a surface sensing system (134). The surface sensing system(134) may include sensors for sensing characteristics of substances,including production (121), passing through or otherwise located in thewell surface system (124). The characteristics may include, for example,pressure, temperature and flow rate of production (121) flowing throughthe wellhead (130), or other conduits of the well surface system (124),after exiting the wellbore (120).

In some embodiments, the surface sensing system (134) includes a surfacepressure sensor (136) operable to sense the pressure of production (121)flowing through the well surface system (124), after it exits thewellbore (120). The surface pressure sensor (136) may include, forexample, a wellhead pressure sensor that senses a pressure of production(121) flowing through or otherwise located in the wellhead (130). Insome embodiments, the surface sensing system (134) includes a surfacetemperature sensor (138) operable to sense the temperature of production(121) flowing through the well surface system (124), after it exits thewellbore (120). The surface temperature sensor (138) may include, forexample, a wellhead temperature sensor that senses a temperature ofproduction (121) flowing through or otherwise located in the wellhead(130), referred to as “wellhead temperature” (T_(wh)). In someembodiments, the surface sensing system (134) includes a flow ratesensor (139) operable to sense the flow rate of production (121) flowingthrough the well surface system (124), after it exits the wellbore(120). The flow rate sensor (139) may include hardware that senses aflow rate of production (121) (Q_(wh)) passing through the wellhead(130).

In some embodiments, the well system (106) includes a reservoirsimulator (160). For example, the reservoir simulator (160) may includehardware and/or software with functionality for generating one or morereservoir models regarding the hydrocarbon-bearing formation (104)and/or performing one or more reservoir simulations. For example, thereservoir simulator (160) may store well logs and data regardingreservoir samples for performing simulations. For example, the reservoirsamples may include core samples and/or condensate fluids sampleobtained from the reservoir. A reservoir simulator may further analyzethe well log data, the reservoir sample data, seismic data, and/or othertypes of data to generate and/or update the one or more reservoirmodels. While the reservoir simulator (160) is shown at a well site,embodiments are contemplated where reservoir simulators are located awayfrom well sites. In some embodiments, the reservoir simulator (160) mayinclude a computer system that is similar to the computer system (900)described below with regard to FIG. 4 and the accompanying description.

FIG. 1B shows details of the reservoir simulator (160) depicted in FIG.1A above in accordance with one or more embodiments disclosed herein. Asshown in FIG. 1B, the reservoir simulator (160) has multiple components,including, for example, a buffer (114), an Equation of State (EoS)configuration engine (111), a simulation engine (112), and a pressuretemperature (P-T) diagram analysis engine (113). Each of thesecomponents is discussed below.

In one or more embodiments, the buffer (114) may be implemented inhardware (i.e., circuitry), software, or any combination thereof. Thebuffer (114) is configured to store input data, output results, andintermediate data of the EoS configuration engine (111), the simulationengine (112), and the P-T diagram analysis engine (113). In one or moreembodiments, the buffer (114) stores condensate composition (115),condensate liquid dropout curve (116), EoS (117), P-T diagrams (118),and flue gas ratio (119). The condensate composition (115) is acomposition measure of the condensate obtained from a gas condensatereservoir. For example, the condensate composition (115) may indicatethe type of condensate as lean, medium, or rich based on relative amountof heavier hydrocarbons versus lighter hydrocarbons in the condensate.For example, the molar percentage of C7+ in example lean, medium, andrich condensates may be 5.6%, 11.2%, and 14.8%, respectively. Thecondensate liquid dropout curve (116) describes the relationship ofliquid phase volume percentage versus pressure of the condensateobtained from a gas condensate reservoir. The condensate liquid dropoutcurve (116) may be formatted as a data plot or in other data formatssuch as value pairs of volume percentage versus pressure. The EoS (117)is a thermodynamic equation relating states of the condensate under agiven set of physical conditions, such as pressure, volume, temperature,or internal energy. For example, the EoS (117) may be based onPeng-Robinson Equation of State. The P-T diagrams (118) describe thephases of the condensate obtained from a gas condensate reservoir. TheP-T diagrams (118) may be formatted as data plots or in other dataformats such as pressure-temperature value pairs. In the P-T diagrams(118), the line that separates the solid and vapor phases is referred tothe as sublimation line, the line that separates the solid and liquidphases is referred to the as the fusion line, and the line thatseparates the liquid and vapor phases is referred to as the vaporizationline. The sublimation line, the fusion line, and the vaporization linecollectively form the fluid envelope and the point where the three linesmeet is referred to as the triple point. In other words, the triplepoint is the only point where all three phases can exist in equilibrium.The point where the vaporization line ends is referred to as thecritical point. The critical point is also referred to as the saturationpoint as the point is where the saturated liquid and saturated vaporlines meet. Past this point, it is impossible for a liquid/vaportransformation to occur. The flue gas ratio (119) is the volume ratiobetween components of the flue gas, such as nitrogen, carbon dioxide,carbon monoxide, water vapor, sulfur dioxide, etc.

In one or more embodiments, the EoS configuration engine (111) may beimplemented in hardware (i.e., circuitry), software, or any combinationthereof. In one or more embodiments, a condensate fluids sample (e.g.,having the condensate composition (115)) is obtained from the gascondensate reservoir for a laboratory pressure, volume and temperature(PVT) experiment. The EoS configuration engine (111) is configured toperform simulation of the laboratory PVT experiment based on Equationsof State (EoS) (117) of the condensate to generate a simulated liquiddropout curve. By iteratively performing the simulation, the EoS (117)is adjusted to match the simulated liquid dropout curve and the liquiddropout curve (116) generated by physically performing the laboratoryPVT experiment.

In one or more embodiments, the simulation engine (112) may beimplemented in hardware (i.e., circuitry), software, or any combinationthereof. In particular, the simulation engine (112) is configured toperform a reservoir simulation of the gas condensate reservoir underinjection of flue gas. The reservoir simulation is performed based onthe adjusted EoS (117) to model the condensate banking phenomena.

In one or more embodiments, the P-T diagram analysis engine (113) may beimplemented in hardware (i.e., circuitry), software, or any combinationthereof. In particular, the P-T diagram analysis engine (113) isconfigured to analyze P-T diagrams (118) generated based on the resultsof the reservoir simulation to determine an optimal value of the fluegas ratio (119) for improving the condensate production.

In one or more embodiments, the EoS configuration engine (111), thesimulation engine (112), and the P-T diagram analysis engine (113)collectively perform the functionalities described above using themethod described in reference to FIG. 2 below.

Although the reservoir simulator (160) is shown as having fourcomponents (111, 112, 113, 114), in other embodiments, the reservoirsimulator (160) may have more or fewer components. Further, thefunctionality of each component described above may be split acrossmultiple components. Further still, each component (111, 112, 113, 114)may be utilized multiple times to carry out an iterative operation.

FIG. 2 shows a flowchart in accordance with one or more embodimentsdisclosed herein. One or more of the steps in FIG. 2 may be performed bythe components of the well environment (100) and the reservoir simulator(160), discussed above in reference to FIGS. 1A-1B. In one or moreembodiments, one or more of the steps shown in FIG. 2 may be omitted,repeated, and/or performed in a different order than the order shown inFIG. 2 . Accordingly, the scope of the disclosure should not beconsidered limited to the specific arrangement of steps shown in FIG. 2.

Referring to FIG. 2 , initially in Step 200, laboratory pressure, volumeand temperature (PVT) experiments are performed using a condensatefluids sample obtained from a gas condensate reservoir. Each PVTexperiment mimics a form of phase behavior progression during productionof the condensate fluids from the gas condensate reservoir to thesurface facilities during the gas condensate reservoir production. Forexample, the PVT experiments may include a constant volume depletion(CVD) test that generates, among others, a liquid dropout curve and acomposition measure of the condensate fluids sample.

Based on the composition measure of the condensate fluids sample, theEquations of state (EoS) is configured to simulate the PVT experimentsand generate a simulated liquid dropout curve. The EoS is iterativelyadjusted (i.e., tuned) to match the simulated liquid dropout curve andthe liquid dropout curve generated by the PVT experiments. In one ormore embodiments, the critical pressure, critical temperature, andacentric factor are the parameters used to tuned the Equation of State.

In Step 201, a reservoir simulation is performed to model the condensatebanking phenomena of the gas condensate reservoir. Specifically, thereservoir simulation is performed based on the EoS configured in Step200 above to generate pressure-temperature data of the condensate fluidsand/or a mixture of condensate fluids and injected flue gas with varyingflue gas ratio. In particular, the simulation models the flue gasinjection and considers flue gas flow rate and pressure in addition tothe flue gas ratio. In one or more embodiments, the simulation isperformed multiple times, referred to as simulation scenarios, for eachof a set of selected flue gas ratios to generate a corresponding measureof condensate production. The range of selected flue gas ratio dependson the gas composition and simulation scenarios to identify the ratiosneeded to maximize condensate recovery.

In Step 202, the simulated pressure-temperature data is analyzed toidentify an optimal ratio of flue gases (referred to as the optimal fluegas ratio) based on different simulation scenarios to maximize themeasure of condensate production. For example, the measure of condensateproduction may correspond to the production flow rate of the condensate.The optimal flue gas ratio is the volume ratio between carbon dioxide,nitrogen, and oxygen in the flue gas that maximizes the production flowrate of the condensate.

In one or more embodiments, the simulated pressure-temperature data isplotted as P-T diagrams for analysis. Including the flue gas with theoptimal flue gas ratio in the condensate adjusts the critical orsaturation point in the P-T diagrams such that early precipitation ofcondensate in the condensate banking phenomena is delayed to improve thecondensate recovery.

In Step 203, the proper case is identified that will assist inmaximizing the recovery factor. In one or more embodiments, the propercase is based on a cumulative gas condensate production, i.e., cumulatedproduction flow rate of the condensate.

In Step 204, the flue gas with the optimal flue gas ratio is injectedinto the gas condensate reservoir to improve recovery of condensateproduction in the gas condensate reservoir. In one or more embodiments,the flue gas is injected into the gas condensate reservoir through theproduction wellbore. In alternative embodiments, the flue gas isinjected into the gas condensate reservoir through an injection welladjacent to the production wellbore. In one or more embodiments, theflue gas is produced in a furnace at the wellsite and directed to thewellbore through the smoke flue and connecting pipes.

FIGS. 3A-3C shows an implementation example in accordance with one ormore embodiments. Gas condensate reservoirs have a significant share ofthe world's gas supply. Recovered condensate of these reservoirs has ahigh value in the market. However, when the reservoir pressure declinesbelow the dew point pressure, liquid may drop out of gas condensateinside the reservoir and may leave a significant part of the condensateirrecoverable. In particular, the recovery factor for rich gascondensate reservoirs is very low due to severe condensate bankingphenomena. The implementation example shown in FIGS. 3A-3C is based onthe system and method flowchart described in reference to FIGS. 1A, 1B,and 2 above that modify the reservoir fluid phase envelop by flue gasinjection to improve the recovery of condensate and realize the economicvalue of the gas field.

Specifically, FIGS. 3A-3C shows an example of a P-T diagram (301) of theunmodified condensate in the gas reservoir, a P-T diagram (302) of thecondensate with injected carbon dioxide in the gas reservoir, and a P-Tdiagram (303) of the condensate with injected flue gas of the optimalflue gas ratio in the gas reservoir. The critical points in the P-Tdiagrams (301, 302, 303) are marked by “X”. The critical point in theP-T envelope of the P-T diagram (303) is adjusted from those of the P-Tdiagram (301) and P-T diagram (302) to optimally delaying the earlyprecipitation of condensate and improving gas recovery. After injectionof the flue gases, the flue gases react with formation fluid and changeits composition and properties, which results in lowering the dew pointpressure thereby postponing the condensate banking phenomena. Forexample, the dew point of the unmodified condensate in the gas reservoiris at 2700 psi and 170° F., while the dew point pressure is reduced to2550 psi with injected flue gas of the optimal flue gas ratio in the gasreservoir.

Embodiments disclosed herein may be implemented on virtually any type ofcomputing system, regardless of the platform being used. For example,the computing system may be one or more mobile devices (e.g., laptopcomputer, smart phone, personal digital assistant, tablet computer, orother mobile device), desktop computers, servers, blades in a serverchassis, or any other type of computing device or devices that includesat least the minimum processing power, memory, and input and outputdevice(s) to perform one or more embodiments. For example, as shown inFIG. 4 , the computing system (400) may include one or more computerprocessor(s) (402), associated memory (404) (e.g., random access memory(RAM), cache memory, flash memory, etc.), one or more storage device(s)(406) (e.g., a hard disk, an optical drive such as a compact disk (CD)drive or digital versatile disk (DVD) drive, a flash memory stick,etc.), and numerous other elements and functionalities. The computerprocessor(s) (402) may be an integrated circuit for processinginstructions. For example, the computer processor(s) may be one or morecores, or micro-cores of a processor. The computing system (400) mayalso include one or more input device(s) (410), such as a touchscreen,keyboard, mouse, microphone, touchpad, electronic pen, or any other typeof input device. Further, the computing system (400) may include one ormore output device(s) (408), such as a screen (e.g., a liquid crystaldisplay (LCD), a plasma display, touchscreen, cathode ray tube (CRT)monitor, projector, or other display device), a printer, externalstorage, or any other output device. One or more of the output device(s)may be the same or different from the input device(s). The computingsystem (400) may be connected to a network (412) (e.g., a local areanetwork (LAN), a wide area network (WAN) such as the Internet, mobilenetwork, or any other type of network) via a network interfaceconnection (not shown). The input and output device(s) may be locally orremotely (e.g., via the network (412)) connected to the computerprocessor(s) (402), memory (404), and storage device(s) (406). Manydifferent types of computing systems exist, and the aforementioned inputand output device(s) may take other forms.

Software instructions in the form of computer readable program code toperform embodiments of the disclosure may be stored, in whole or inpart, temporarily or permanently, on a non-transitory computer readablemedium such as a CD, DVD, storage device, a diskette, a tape, flashmemory, physical memory, or any other computer readable storage medium.Specifically, the software instructions may correspond to computerreadable program code that when executed by a processor(s), isconfigured to perform embodiments disclosed herein.

Further, one or more elements of the aforementioned computing system(400) may be located at a remote location and be connected to the otherelements over a network (412). Further, one or more embodiments may beimplemented on a distributed system having a plurality of nodes, whereeach portion of the disclosure may be located on a different node withinthe distributed system. In one embodiment, the node corresponds to adistinct computing device. Alternatively, the node may correspond to acomputer processor with associated physical memory. The node mayalternatively correspond to a computer processor or micro-core of acomputer processor with shared memory and/or resources.

While the invention has been described with respect to a limited numberof embodiments, those skilled in the art, having benefit of thisdisclosure, will appreciate that other embodiments can be devised whichdo not depart from the scope of the disclosure as disclosed herein.Accordingly, the scope of the disclosure should be limited only by theattached claims.

What is claimed:
 1. A method to improve production of condensate in agas condensate reservoir, comprising: obtaining a condensate fluidssample from the gas condensate reservoir; generating, from a laboratorypressure, volume and temperature (PVT) experiment of the condensatefluids sample, a liquid dropout curve of the condensate fluids sample;performing simulation of the laboratory PVT experiment based onEquations of State (EoS) of the condensate to generate a simulatedliquid dropout curve, wherein the EoS is adjusted to match the simulatedliquid dropout curve and the liquid dropout curve generated by thelaboratory PVT experiment; performing, based on the adjusted EoS, areservoir simulation of the gas condensate reservoir under injection offlue gas, wherein the reservoir simulation models a condensate bankingphenomenon to generate an optimal flue gas ratio that maximizes ameasure of condensate production; and facilitating, based on the optimalflue gas ratio, the production of the condensate in the gas condensatereservoir.
 2. The method of claim 1, further comprising: furthergenerating, from the laboratory PVT experiment of the condensate fluidssample, a composition measure of the condensate fluids sample; andconfiguring, based on the composition measure, the EoS for simulatingthe PVT experiment.
 3. The method of claim 2, wherein the compositionmeasure identifies the condensate fluids sample as one of a leancomposition type, a medium composition type, and a rich compositiontype.
 4. The method of claim 1, further comprising: generating, based onsimulated pressure-temperature (P-T) data from the reservoir simulationof the gas condensate reservoir under injection of flue gas, a pluralityof P-T diagrams corresponding to a plurality of flue gas ratios; andanalyzing the plurality of the P-T diagrams to select an optimal P-Tdiagram where a critical point is optimally adjusted to delay earlyprecipitation of condensate in the condensate banking phenomenon,wherein the optimal P-T diagram corresponds to the optimal flue gasratio.
 5. The method of claim 1, further comprising: injecting, into thegas condensate reservoir during production of the condensate, the fluegas based on the optimal flue gas ratio.
 6. The method of claim 5,wherein the flue gas is injected via a production wellbore of the gascondensate reservoir during the production of the condensate.
 7. Themethod of claim 5, wherein the flue gas is injected via an injectionwell in a vicinity of the production wellbore.
 8. The method of claim 5,wherein the flue gas is produced from combustion in a furnace at awellsite of the gas condensate reservoir.
 9. A reservoir simulator toimprove production of condensate in a gas condensate reservoir,comprising: a computer processor; and memory storing instructions, whenexecuted, causing the computer processor to: perform, based on Equationsof State (EoS) of the condensate, simulation of a laboratory pressure,volume and temperature (PVT) experiment of a condensate fluids sampleobtained from the gas condensate reservoir to generate a simulatedliquid dropout curve, wherein the EoS is adjusted to match the simulatedliquid dropout curve and a liquid dropout curve generated by performingthe laboratory PVT experiment; perform, based on the adjusted EoS, areservoir simulation of the gas condensate reservoir under injection offlue gas, wherein the reservoir simulation models a condensate bankingphenomenon to generate an optimal flue gas ratio that maximizes ameasure of condensate production; and facilitate, based on the optimalflue gas ratio, the production of the condensate in the gas condensatereservoir.
 10. The reservoir simulator of claim 9, the instructions,when executed, further causing the computer processor to: furthergenerate, from the laboratory PVT experiment of the condensate fluidssample, a composition measure of the condensate fluids sample; andconfigure, based on the composition measure, the EoS for simulating thePVT experiment.
 11. The reservoir simulator of claim 10, wherein thecomposition measure identifies the condensate fluids sample as one of alean composition type, a medium composition type, and a rich compositiontype.
 12. The reservoir simulator of claim 9, the instructions, whenexecuted, further causing the computer processor to: generate, based onsimulated pressure-temperature (P-T) data from the reservoir simulationof the gas condensate reservoir under injection of flue gas, a pluralityof P-T diagrams corresponding to a plurality of flue gas ratios; andanalyze the plurality of the P-T diagrams to select an optimal P-Tdiagram where a critical point is optimally adjusted to delay earlyprecipitation of condensate in the condensate banking phenomenon,wherein the optimal P-T diagram corresponds to the optimal flue gasratio.
 13. The reservoir simulator of claim 9, wherein the flue gas isinjected into the gas condensate reservoir during the production of thecondensate based on the optimal flue gas ratio.
 14. The reservoirsimulator of claim 13, wherein the flue gas is injected via a productionwellbore of the gas condensate reservoir or an injection well in avicinity of the production wellbore, and wherein the flue gas isproduced from combustion in a furnace at a wellsite of the gascondensate reservoir.
 15. A system comprising: a wellsite for productionof condensate in a gas condensate reservoir; and a reservoir simulatorcomprising a computer processor and memory storing instructions, whenexecuted, causing the computer processor to: perform, based on Equationsof State (EoS) of the condensate, simulation of a laboratory pressure,volume and temperature (PVT) experiment of a condensate fluids sampleobtained from the gas condensate reservoir to generate a simulatedliquid dropout curve, wherein the EoS is adjusted to match the simulatedliquid dropout curve and a liquid dropout curve generated by performingthe laboratory PVT experiment; perform, based on the adjusted EoS, areservoir simulation of the gas condensate reservoir under injection offlue gas, wherein the reservoir simulation models a condensate bankingphenomenon to generate an optimal flue gas ratio that maximizes ameasure of condensate production; and facilitate, based on the optimalflue gas ratio, the production of the condensate in the gas condensatereservoir.
 16. The system of claim 15, the instructions, when executed,further causing the computer processor to: further generate, from thelaboratory PVT experiment of the condensate fluids sample, a compositionmeasure of the condensate fluids sample; and configure, based on thecomposition measure, the EoS for simulating the PVT experiment.
 17. Thesystem of claim 16, wherein the composition measure identifies thecondensate fluids sample as one of a lean composition type, a mediumcomposition type, and a rich composition type.
 18. The system of claim15, the instructions, when executed, further causing the computerprocessor to: generate, based on simulated pressure-temperature (P-T)data from the reservoir simulation of the gas condensate reservoir underinjection of flue gas, a plurality of P-T diagrams corresponding to aplurality of flue gas ratios; and analyze the plurality of the P-Tdiagrams to select an optimal P-T diagram where a critical point isoptimally adjusted to delay early precipitation of condensate in thecondensate banking phenomenon, wherein the optimal P-T diagramcorresponds to the optimal flue gas ratio.
 19. The system of claim 15,wherein the flue gas is injected into the gas condensate reservoirduring the production of the condensate based on the optimal flue gasratio.
 20. The system of claim 15, wherein the flue gas is injected viaa production wellbore of the gas condensate reservoir or an injectionwell in a vicinity of the production wellbore, and wherein the flue gasis produced from combustion in a furnace at the wellsite of the gascondensate reservoir.